The Masela LNG Plant Location – Yamdena Island

Masela LNG - 75341025_2575149926055521_9059067100873621504_n

The Inpex Abadi Masela LNG plant will be built on Yamdena Island in Kabupaten Kepulauan Tanimbar of the Province of Maluku. Yamdena island is the biggest island among the Tanimbar Islands.

The head of SKK Migas, Bapak Dwi Sutjipto, handed the documents related to the plant location plan to the governor of Maluku, Bapak Murad Ismail on November 4, 2019, in Ambon. The event was attended by Mr. Akihiro Watanabe from Inpex and Mr. Lucki Wattimury.

This is a significant positive step to accelerate the construction of the Abadi Masela LNG plant. The LNG plant is designed to produce 9.5 million tons of LNG annually.

In this event, the governor of Maluku stated that the local government of Maluku welcomes the project and will give their full support in the land acquisition and construction of the LNG plant.

The total investment of the huge Abadi Masela project estimated at around US$20 billion will be the biggest project in Indonesia. During the development phase, the project will employ around 30,000 workers.

The natural gas to feed the LNG plant will come from the giant offshore Abadi gas field which was discovered by Inpex in 2000. The Abadi field has the capacity to produce more than 1 billion SCF of gas per day and 20,000 barrels of condensate per day for 24 years.

Inpex Indonesia owns 65 percent share of the Abadi Masela project and Shell has the remaining 35 percent. Inpex will operate the field until 2055.

This information is adapted from the Facebook post of Mr. Rinto Pudyantoro.

The Giant Carcara and the Pre-Salt Basin

A semisubmersible drilling rig

 

The Giant Carcara Oil Field

The giant Carcara is a pre-salt oil and gas field located in the Santos basin offshore Brazil. It lies in water depths of 2027 meters and is one of the biggest discoveries in the world. It was discovered by Petrobras in 2012.

The oil reservoir lies in the pre-salt layer and its total thickness is more than 400 meters. It is estimated to contain recoverable reserves of more than one billion barrels of oil.

Operated by Equinor, oil production from the Carcara field is scheduled to start in 2024. Two FPSOs will be used to produce the oil and gas.

The Interesting Pre-Salt Basins

Oil was discovered in the Pre-Salt Basin in offshore Brazil in 2005. Oil-rich formations sit deep in the water and under thick layers of rock and salt.

Pre-salt basins were formed more than 100 million years ago when the South American and African continents separated, and therefore pre-salt layers are especially common off the coast of Africa and Brazil.

The hydrocarbon sits under layers of salt formations that are 2000 meters thick. The pre-salt production rates are some of the highest in the world for deepwater fields.

In Africa, the first pre-salt oil discoveries took place in Angola in 1983. The presence of pre-salt basins in eastern offshore Brazil and western offshore of Africa is proof that the South American and African continents were connected at one time.

Balikpapan – The Most Interesting Oil Town of Indonesia

City of Balikpapan - Photo by Uut Minhudan
The city of Balikpapan – Photo courtesy of Uut Minhudan

Balikpapan, located in East Kalimantan, is the most well known and interesting oil town in Indonesia, and possibly in the world. It is at the center of oil and gas exploration and production activities that have been taking place in East Kalimantan since 1897 when the first oil well was drilled in Balikpapan. It is also the battleground of two fierce battles during World War II. It is set to become even more well known with the announcement of the relocation of the capital city of Indonesia from Jakarta to East Kalimantan.

Here are the interesting facts about Balikpapan.

The first oil discovery in Balikpapan

Oil was discovered in Balikpapan in 1897 when Jacobus Hubertus Menten, a Dutch mining engineer observed oil seepages in the area. With the help from Sir Marcus Samuel from Shell Transport and Trading Ltd, they drilled the famous Well Mathilda B-1 on 10 February 1897. The well was drilled to 222 Meter and it flowed initially at 184 barrels per day. This oil discovery in Balikpapan took place 38 years after Sir Edwin Drake drilled the world’s first oil well in America.

With the discovery, Jacobus Hubertus Menten and Sir Marcus Samuel formed Nederlandsch Indisch Industrie en Handel Maatschappij (NIIHM), and it continued to discover other oil fields away from Balikpapan. 10 February 1897 is considered the birth date of Balikpapan.

The Balikpapan Refinery

To process the crude oil from the surrounding area and to meet the needs for fuel, the oil refinery of Balikpapan was completed in 1922 by BPM (Bataafsche Petroleum Maatschappij) which was a subsidiary of Royal Dutch Shell. The Balikpapan refinery was damaged in 1942 when the Japanese army invaded Balikpapan. The refinery was controlled by the Japanese army in 1942-1945. BPM regained control of the refinery after the Allied forces ended the Japanese occupation of Balikpapan in 1945.

Several years later, Pertamina gained control of the refinery in 1949. The refinery has been expanded and upgraded several times to meet the increasing demand for fuel in the eastern part of Indonesia.

As one of the largest refineries in Indonesia, it is set to become even bigger. It is currently undergoing a large 4-billion-dollar expansion which will increase its processing capacity from 260,000 barrels per day to 360,000 barrels per day when it is completed in 2021. The refinery will have the capability to produce high-quality Euro V standard fuels.

The Discovery of Giant Oil and Gas Fields

Balikpapan experienced its biggest boom when several large international oil companies came to town after the production sharing contract scheme was introduced by Indonesia in 1966.

Balikpapan was the base of Union Oil of California (Unocal), Total and Roy M. Huffington Incorporated (Huffco) during their exploration and production operations in East Kalimantan where they discovered several giant oil and gas fields.

Pertamina has a huge presence in Balikpapan since 1949 when it took over the oilfields and the refinery which were previously operated by BPM (Bataafsche Petroleum Maatschappij), a subsidiary of Royal Dutch Shell.

Operated from Balikpapan, Unocal in partnership with Japex discovered the giant offshore oil field of Attaka in 1970. It also discovered the offshore Sepinggan field and the Yakin field both of which are clearly visible from the hills at Balikpapan. In 1996, Unocal discovered and developed the West Seno field which is the first deepwater oil field in Indonesia.

Total with its partner, Inpex, acquired the Mahakam Block in 1966. They discovered several giant offshore oil and gas fields: Handil, Peciko, Tambora, Bekapai, South Mahakam, Sisi-Nubi, and Tunu.

Huffco discovered the giant onshore Badak gas field in 1970 in East Kalimantan. The discovery of the giant Badak gas field had a huge influence on the course of oil and gas development in East Kalimantan. It prompted Huffco and Pertamina of Indonesia to build an LNG plant making it possible to export the gas.

Besides the Badak field, Huffco subsequently discovered the Nilam, Pamaguan, Semberah, Mutiara, Beras, and Lempake fields.

Huffco later became known as VICO Indonesia (Virginia Indonesia Company) in 1990 after Mr. Roy M. Huffinton sold the company.

After the introduction of the production sharing contract scheme  (PSC) in 1966, and with the discovery of several giant oil and fields in East Kalimantan and in other parts of Indonesia, crude oil production in Indonesia increased from 500,000 BOPD to 1,650,000 BOPD at its peak in 1977.

The Badak LNG Plant in Bontang

The LNG plant known as the Badak LNG was completed in 1977. Located in Bontang, besides processing the gas produced by Huffco from the Badak field, the Badak LNG plant also processes gas produced from the fields operated by Unocal and Total located in East Kalimantan. Up until the completion of the LNG plant, most of the associated gas produced by Unocal and Total were flared.

The Badak LNG plant initially comprised of two trains. Over the years, with new field discoveries, six additional trains were constructed. With 22.5 million tons per year LNG production capacity, it is one of the largest LNG plants in the world.

As of 16 September 2019, Badak LNG has delivered 9445 LNG cargoes to countries such as Japan, Taiwan, Korea, China, USA, Russia, and India. 

The Fierce Battlefield during World War II

Being rich in oil and having a refinery, Balikpapan was so vital that it became a battlefield twice during World War II.

The battle of Balikpapan in 1942

During World War II, in order to control the supply of fuel, Japan invaded Balikpapan in 1942. The Dutch garrison resisted the invasion but eventually was defeated by the much bigger Japanese forces. The refinery was partially destroyed during the invasion. Japanese forces took control of Balikpapan, oil production and the refinery from 1942 to 1945.

The Battle of Balikpapan in 1945

To regain control of Balikpapan and the oil supply, the Allied forces directed by General Douglas McArthur and spearheaded by the Australian 7th Division invaded Balikpapan on 25 June 1945. After 3 weeks of fierce fighting and heavy bombing, the Japanese soldiers in Balikpapan finally surrendered on 21 July 1945. Many Japanese soldiers fought to the end in the battle. There is a Japanese cemetery hidden among the hills in Balikpapan.

The Coal Boom of Balikpapan in the 1990s

Balikpapan experienced another economic boom when it became the center of the booming coal production in East Kalimantan beginning in the 1990s.

The Balikpapan Coal Terminal completed in 1995 is one of the biggest coal terminals in Indonesia. It has a throughput capacity of 15 million tons of coal annually.

Will Balikpapan continue to boom?

Since the discovery of the first oil well in Balikpapan in 1897, Balikpapan has seen several booms in the last 120 years. It has grown from a small fishing village to become a city with a population of 850,000 today.

On 26 August 2019, the President of Indonesia, Joko Widodo, announced that Indonesia will relocate its capital city from Jakarta to East Kalimantan. As the main gateway to East Kalimantan, Balikpapan will be the center of activities during the construction of a new capital of Indonesia. So, Balikpapan will likely continue to boom.

Finally, Balikpapan indeed is a very interesting town. As an oil and coal mining town, it has been voted several times as the most liveable city in Indonesia.  Thousands of oil people from around the world have worked and lived here. Many children of international expatriates and Indonesian oil professionals from Java, Sumatera and other parts of Indonesia grew up in Balikpapan. Most of them have fond memories of Balikpapan.

Many sons and daughters of the first-generation Indonesia oil professionals follow the footsteps of their parents to work for oil companies in Balikpapan. There is a saying in Balikpapan whoever has drunk the water of Balikpapan will surely return. The writer of this article lived and worked for Unocal in Balikpapan from 1976 to 1980, and he has returned to visit this interesting place many times.

Jamin Djuang

The Job of a Subsea Engineer in Deepwater Drilling

Subsea engineers are the crew that works with all the equipment and operations that are performed between the drill-floor and the seabed on floating offshore drilling rigs.  The “SUBSEA” crew is employed by the drilling contractor and is an integral part of the offshore operations.

Subsea Operations

The subsea crew is responsible for implementing and maintaining the structures, tools, and equipment used in the underwater components of offshore oil and gas drilling and production operations.

The underwater environment presents unique challenges to subsea engineers, particularly deepwater operations where temperature, pressure, and corrosion test the durability of submerged equipment and tools. Most subsea engineering operations depend on automation and remote procedures to construct, maintain and repair components beneath the surface of the water.

To understand what tasks the subsea team is required to undertake we first need to explore the key structures between the seabed and the drill-floor that connect the drilling unit to the wellbore. There’s also a lot of technology hiding beneath the surface of the water. Starting from the seabed and working our way up to the drill-floor we’ll look at the subsea components that help us bring drill cuttings and potentially trapped hydrocarbons safely to surface.

With the deepest-water offshore well ever to be drilled lying in 3,400 m (11,155 ft) of water, it’s easy to see why a team of specialists needs to be employed to oversee the operations that happen beneath the waves.

Subsea Wellhead

The subsea wellhead system is a pressure-containing vessel that provides a means to hang off and seal off casing used in drilling the well. The wellhead also provides a profile to latch the subsea blowout preventer (BOP) stack and drilling riser back to the floating drilling rig. In this way, access to the wellbore is secure in a pressure-controlled environment. The subsea wellhead system is located on the ocean floor and must be installed remotely with running tools and drill-pipe.

subsea wellhead

Figure 1 – Subsea wellhead

The subsea wellhead inside diameter (ID) is designed with a landing shoulder located in the bottom section of the wellhead body. Subsequent casing hangers land on the previous casing hanger installed. The casing is suspended from each casing-hanger top and accumulates on the primary landing shoulder located in the ID of the subsea wellhead. Each casing hanger is sealed off against the ID of the wellhead housing and the outside diameter (OD) of the hanger itself with a seal assembly that incorporates a true metal-to-metal seal. This seal assembly provides a pressure barrier between casing strings, which are suspended in the wellhead.

A standard subsea wellhead system will typically consist of the following:

  • Drilling guide base.
  • Low-pressure housing.
  • High-pressure wellhead housing.
  • Casing hangers (various sizes, depending on casing program).
  • Metal-to-metal annulus sealing assembly.
  • Bore protectors and wear bushings.
  • Running and test tools.

The drilling guide base provides a means for guiding and aligning the BOP onto the wellhead. Guidewires from the rig are attached to the guideposts of the base, and the wires are run subsea with the base to provide guidance from the rig down to the wellhead system.

Subsea Blowout Preventer (BOP)

There are two means to prevent an escape of high-pressure fluids or gases from the well when drilling for oil and gas.

The primary means is the hydrostatic pressure from the weighted up drilling mud and the second means is the blowout preventer. The BOP is literally the last line of defense in preventing a catastrophic event on the rig.

The BOP is an arrangement of valves, rams preventers, annular preventers, connectors, and control system that can be controlled from the surface to “shut-in” the well in the event of an impending blowout.

In addition to controlling the downhole pressure and the flow of oil and gas, blowout preventers are intended to prevent tubing, tools and drilling fluid from being blown out of the wellbore when a blowout threatens. Blowout preventers are critical to the safety of the crew, rig, and environment, and to the monitoring and maintenance of well integrity.

subsea blowout preventer - BOP

Figure 2 – A Subsea BOP

With the wellhead just above the mudline on the seafloor, there are four primary ways by which a BOP can be controlled. The possible means are:

  • Electrical Control Signal: sent from the surface through a control cable;
  • Acoustical Control Signal: sent from the surface based on a modulated/encoded pulse of sound transmitted by an underwater transducer;
  • ROV Intervention: remotely operated vehicles (ROVs) mechanically control valves and provide hydraulic pressure to the stack (via “hot stab” panels);
  • Deadman Switch / Auto Shear: fail-safe activation of selected BOPs during an emergency, and if the control, power and hydraulic lines have been severed.

Two control pods are provided on the BOP for redundancy. Electrical signal control of the pods is primary. Acoustical, ROV intervention and dead-man controls are secondary.

An emergency disconnect system, or EDS, disconnects the rig from the well in case of an emergency. The EDS is also intended to automatically trigger the deadman switch, which closes the BOP, kill and choke valves. The EDS may be a subsystem of the BOP stack’s control pods or separate.

Pumps on the rig normally deliver pressure to the blowout preventer stack through hydraulic lines. Hydraulic accumulators on the BOP stack enable closure of blowout preventers even if the BOP stack is disconnected from the rig. It is also possible to trigger the closing of BOPs automatically based on too high pressure or excessive flow.

The subsea team

The subsea team is responsible for all maintenance and testing of the BOP and its ancillary equipment. Function tests are carried out frequently throughout the drilling program, especially prior to running “the stack” from the surface, and also prior to drilling through expected reservoir formations.

The drilling crew and subsea team run coordinated tests from both the drill-floor and the backup system’s control panel within the accommodation unit. Every rig must have a BOP control panel at the driller’s station as well as one in a safe location away from the drill floor.

Subsea BOP control panel

Figure 3 – A BOP control panel

The members of a subsea team are generally recruited with an electrical or mechanical trade base or engineering degree and they then go through extensive training programs to familiarize themselves with the subsea operations. Because of the skills required to be able to competently do their job these crew members don’t start working offshore as an unskilled laborer like many of the drilling crew members generally do. Subsea operations are a highly specialized field and as such, highly specialized teams are required to perform the tasks involved.

It is also one of the most highly regulated areas in the offshore drilling industry due to the fact that failures in the system can result in catastrophic events, such as the Deepwater Horizon disaster. Being the last line of defense in the event of a blowout, it is critical that all the subsea equipment can be reliably called upon to shut the well in during a well control emergency situation.

Because the BOP is such a critical part of the process safety systems offshore, since the Macondo blowout there have been strict regulatory requirements imposed on the industry to ensure the operators have clear programs in place to identify potential hazards when they drill, clear protocol for addressing those hazards, and strong procedures and risk-reduction strategies for all phases of activity, from well design and construction to operation, maintenance, and decommissioning.

Adhering to these regulations requires certification of all subsea equipment from an independent third party regarding the condition, operability, and suitability of the BOP equipment for the intended use and the operator must have all casing designs and cementing program/procedures certified by a professional engineer, verifying the casing design is appropriate for the purpose for which it is intended under expected wellbore conditions.

Third-party verification and inspection organizations work with subsea equipment, specifically BOP and regulatory compliance audits, well-control, and drilling equipment inspections, to ensure the highest levels of integrity within the subsea well control system prior to it being deployed.

Adjoining the top of the BOP and connecting with the bottom of the marine riser is the lower marine riser package.

Lower Marine Riser Package (LMRP)

The LMRP – Lower Marine Riser Package – is the upper section of a two-section subsea BOP stack consisting of the hydraulic connector, annular BOP, ball/flex joint, riser adapter, jumper hoses for the choke, kill and auxiliary lines and subsea control modules. The LMRP interfaces with the BOP stack.

subsea BOP control system

Figure 4 – Subsea BOP control system

Blowout preventers must have completely redundant control systems on the BOP. These control systems are called pods and are designated Blue Pod and Yellow Pod in all systems, no matter which manufacturer. They can be found on the lower marine riser package and are extensively function tested prior to the deployment of the BOP.

There can be as many as six emergency systems in a BOP to operate critical functions in the case of the loss of the primary control system:

  1. Emergency Disconnect Sequence (EDS) – In a case where a dynamically positioned rig has lost the station-keeping ability, the EDS is a one-button system that allows the wellbore to be secured by closing the shear rams. The hydraulic functions to the lower BOP are then vented and the LMRP is separated from the lower BOP by unlatching the connector. An over‐pull is preset on the riser tensioners and the LMRP lifts from the lower BOP. A riser recoil system prevents a slingshot effect. After the EDS button is activated, the sequence takes about 55 seconds maximum.
  2. Acoustic systems – A limited number of emergency functions (typically shear rams and LMRP connector) can be operated from the rig using a hydrophone transmitting to transducers on the BOP. It is uncertain if these systems will work in a well-control situation where considerable noise is generated from flow in the wellbore.
  3. Remote operated vehicles (ROVs) have pumps which can operate functions through a ‘hot stab’ plugged into a dedicated receptacle in the panel. The limitation of an ROV is the time to deploy from the rig to the seabed and the limited flow rate of their pumps.
  4. Deadman systems will close the shear rams in the event all hydraulic and electric control is lost on the BOP. This would typically only happen if the riser string parted. In deepwater if the riser is lost, then the hydrostatic pressure of the drilling mud, which is needed to contain wellbore pressure, would be reduced as it is replaced by seawater. Closing the shear rams secures the well.
  5. Automatic Disconnect System (ADS) closes the shear rams when the lower flex joint reaches a preset angle.
  6. Autoshear closes the shear rams in the event the LMRP is unintentionally disconnected.

The BOP and LMRP are run subsea using the “marine drilling riser” after the top part of the well has been drilled, the conductor casing has been cemented and the wellhead has been landed.

Marine Drilling Riser and Marine Riser Tensioner

A marine drilling riser is a conduit that provides a temporary extension of the subsea oil well to the drilling rig. The “riser” has a large diameter, low-pressure main tube with external auxiliary lines that include high-pressure choke and kill lines for circulating fluids to the subsea blowout preventer (BOP), and usually power and control lines for the BOP.

Drilling riser

Figure 5 – A drilling riser

When used in water depths greater than about 20 meters, the marine drilling riser has to be tensioned to maintain stability.

A marine riser tensioner located on the drilling platform provides a near-constant tension force adequate to maintain the stability of the riser in the offshore environment. The level of tension required is related to the weight of the riser equipment, the buoyancy of the riser, the forces from waves and currents, the weight of the internal fluids, and an adequate allowance for equipment failures.

The marine riser is kept in tension with large pistons operated with an air/oil system at pressures up to 3,000 psi. The riser may be connected via a tensioning ring to wire rope, which is reeved over sheaves on the pistons, or the pistons may be connected directly to the riser tensioner ring.

Riser tensioner

Figure 6 – Riser Tensioner

Once the BOP stack has been successfully run to the seabed with the marine riser and latched onto the wellhead, it will undergo another series of function tests to determine its operability under water-depth conditions.

The density of water can cause problems that can increase dramatically with depth. The hydrostatic pressure at the surface is 14.6 psi (pounds per square inch) but this increases by this amount for every 10 meters of water depth. For a deepwater well that has the wellhead on the seabed in 2,000 meters of water, you would expect to find the hydrostatic pressure acting on the BOP to be around 3,000 psi.

When you also consider the water temperature to be close to 0° Celsius then you can imagine the type of hostile environment these safety-critical components have to function under. Making equipment that can operate under these conditions is the job of the manufacturer’s design engineers,  and making sure they work and keeping them well maintained is the responsibility of the subsea engineers onboard the rig.

Troubleshooting difficult BOP issues generally require collaboration between the design engineers onshore and the subsea engineers and the maintenance crew involved in the offshore operations. When subsea function tests fail then the entire BOP stack and riser string has to be pulled up to the surface so physical examination of the unit can take place.

This is a very time-consuming and costly exercise and therefore making sure everything is functioning 100% before running it down to the seabed is imperative. As anyone who has ever worked offshore knows, it’s all-too-common for BOP’s to fail function tests and this is why such strict regulatory conditions have been placed on the subsea components used for the drilling of offshore wells, especially in deepwater and ultra-deepwater wells. Once the BOP has been successfully tested it’s time to drill ahead!

This article was written by Amanda Barlow, a wellsite geologist and published author of “Offshore Oil and Gas PEOPLE – Overview of Offshore Drilling Operations” for a beginner guide to working in offshore drilling operations, and “An Inconvenient Life – My Unconventional Career as a Wellsite Geologist”.

The Job of A Mudlogger

Mudlogging is one of the many important activities during drilling, especially in exploration drilling. Third-party service providers make up about half of the workforce on an offshore rig. With so many hi-tech and specialized operations being performed at all stages of the drilling operations it’s imperative that experts in their field perform these tasks.

The job of the “mudloggers” is to monitor the drilling operations from the time the well is spudded to the time the well is safely drilled, tested and secured for either production or abandonment.

“Mudlogger” is the generic term used to describe the field specialists who monitor the well and also collect samples for the geologist. The career progression for a mudlogger is to generally start as a sample catcher while they learn about the drilling operations, then progress to a mudlogger and with further experience, become a data engineer.

Sample Catchers

Dedicated sample catchers aren’t always part of the team but they often get “thrown in” as a complementary part of the mudlogging services. They don’t need to have any prior experience in working offshore or as a mudlogger, so it’s a very good entry-level job and is generally the starting position for a graduate geologist (or anyone else) who wishes to work offshore. Although you don’t need to be a geologist to be a sample catcher, most of them will be and will go on to get trained as a mudlogger.

Sample catching is without a doubt the least glamorous and lowest paid of all jobs on the rig…but you have to start somewhere! The role of a sample catcher is to provide the most basic geological data acquisition on the rig and to assist with all general activities when possible. The main duties of the sample catcher are:

  • Ensuring that representative geologic samples are caught throughout the drilling or reaming phases of the well program. This is done by collecting cuttings (drilled rock) samples, from the proper “lagged” (explained below) depths and at the proper intervals as required for evaluation. These samples are collected off the shale shakers, screened and washed, divided into correct portions, and packed into sets for the Client, partners, and government agencies. They may also have to assist in core recovery and packaging as required.
  • Preparing a clean “cuttings” sample on a sample tray for the wellsite geologist and mudlogger, who will then examine it under the microscope and describe the lithology of the drilled formation.
  • Assisting mudloggers and data engineers to perform regular and frequent calibration checks of instruments, perform normal routine maintenance of sensors and other equipment and also assist logging crew with rig-up/rig-down procedures.

 

Shaleshaker-Amanda
A shale shaker

 

The sample catcher reports directly to the mudlogging crew who will ensure his duties are performed correctly. This may include on-the-job training as required. They work out of the mudlogging unit, which is always close to the shale shakers and these are generally one or two levels below the drill floor.

The shale shakers are vibrating screens that separate the drilling fluid from the drilled rock cuttings. The “shaker house” is a very noisy place and double hearing protection must always be worn. There will be multiple shakers to accommodate the large volume of cuttings that can be produced when the drilling rate of penetration is high (i.e. they are drilling fast!). It’s a very “dirty” job and multiple layers of personal protective equipment need to be worn to prevent skin contact with the drilling mud, which can cause serious skin inflammation.

 

Mudloggers and Data Engineers (DE)

Mudloggers and data engineers are responsible for gathering, processing and monitoring information pertaining to drilling operations. They don’t only collect data using specialist data acquisition techniques – they also collect oil samples and detect gases using state-of-the-art equipment.

The information amassed by these guys is analyzed, logged and then communicated to the team that is responsible for the physical drilling of the well. Without the help of the mudlogger, the drilling operations would be less efficient, less cost-effective and much more dangerous. The mudlogger is vital for preventing hazardous situations, such as well blowouts.

They also provide vital assistance to wellsite geologists and write detailed reports based on the data that is collected. Being an entry-level position, employees will be given a mixture of ‘on-the-job’ training and expert in-house training courses, which cover different aspects of drilling operations. A major part of the training will focus on the use of specialist computer software.

Typically, you will need a degree in geology to start a career as a mudlogger. However, candidates with degrees in physics, geochemistry, chemistry, environmental geoscience, maths or engineering may also be accepted.

Along with the sample catchers and data engineers, the mudloggers work out of the mudlogging unit, which is a pressurized sea container-type of office, which is positioned close to the drill floor and shaker house.

The unit will have an air-lock compartment when you first enter it so as to maintain the positive pressure within the unit whenever somebody leaves or enters the unit.

This is the main control room for monitoring the drilling operations and is full of sophisticated and delicate equipment and computer systems. Positive pressure needs to be maintained to ensure the air pressure inside the container is higher than that of the outside area to prevent contamination of sensitive monitoring equipment – and also to ensure the safety of the crew working inside the unit should the outside air become contaminated through uncontrolled releases of hydrocarbons from the well.

 

mudloggingunit-amanda
A mudlogging unit

 

One of the most important tasks of the mudlogger is to oversee the collection of not only geological samples but also mud and gas samples from the well during drilling operations. To be able to do this accurately they have to know the exact “lag time” (or “bottoms-up time”) that it will take for the drilled cuttings or mud and gas to arrive at the surface after being drilled and circulated up the outside of the drill hole (annulus) while suspended in the drilling mud. The lag time maybe a few minutes in a shallow hole or as much as several hours in deep wells with low mud flow rates. To be able to work this time out accurately there are many factors that have to be taken into consideration. The lag time depends on:

  • the annular volume fluid
  • flow rate, which in turn requires knowledge of:
  • dimensions (internal diameter (ID) and outside diameter (OD)) of surface equipment, drill string tubular, casing and riser.
  • mud pump output per stroke, pumping rate, and efficiency.

While the computer’s software will work this out automatically, the calculated value may be incorrect if the operator has entered erroneous or incomplete values for the pipe or hole dimensions, or if the hole is badly washed out. This has to be monitored very carefully to avoid catching mud, gas and cuttings samples at incorrect depths.

Sensors

The mudloggers and DE’s monitor the drilling operations via a series of sensors that are placed at various locations around the drill floor, pit room, and shaker house.

The main drilling and mud parameters that are recorded are: hook movement, weight on hook, standpipe pressure, wellhead pressure, rotary torque, pump strokes, RPM, mud pit levels, mud density, mud temperature, mud resistivity, and mudflow.

These parameters are monitored in real-time and any deviances from the expected normal values must be immediately reported to the driller. The DE will view and monitor all the drilling parameters on a screen as shown below.

drilling parameters-amanda
A drilling parameter screen

 

The five most important monitoring tasks that the mudlogger and DE must watch out for are:

  • Rate of penetration increase, which could indicate they have drilled into a reservoir formation
  • Mud pit volume gain or loss, which could indicate the well is taking a kick, or losing fluid into the formation
  • Mudflow rate change
  • Mud density variation
  • Indication of oil or gas.

The mudlogging unit is a very confined workplace and there may be up to several people working in there at any one time, especially if it’s a “combo” unit, which houses the mudloggers, MWD engineers and possibly also the directional drillers.

Generally (but not always), the same service provider company performs all of these roles so it is quite common for data engineers to progress into a role as an LWD/MWD engineer. Other common career progressions for mudloggers/data engineers are as a wellsite geologist or drilling fluids engineer (mud engineer).

inside a mudlogging unit - amanda
Inside a mudlogging unit

The complete list of responsibilities of the mudloggers is too exhaustive to detail in this article but the above-mentioned roles are the main ones. Like most jobs on the rig, daily reports are a big part of the data engineer’s responsibilities.

The mudloggers report directly to the wellsite geologist, who are generally working in the mudlogging unit alongside them. Because the mudloggers are required to monitor the drilling operations from the commencement of drilling they will always be employed on a permanent rotating roster, which is generally 4-weeks on, 4-weeks off.

This article was written by Amanda Barlow, a wellsite geologist and published author of “Offshore Oil and Gas PEOPLE – Overview of Offshore Drilling Operations” for a beginner guide to working in offshore drilling operations, and “An Inconvenient Life – My Unconventional Career as a Wellsite Geologist”

Another great book you may want to read if you like to get an overview of oil exploration, drilling and production is “The Story of Oil and Gas”: How Oil and Gas Are Explored, Drilled and Produced”.

 

 

The Job of a Wellsite Geologist

The wellsite geologist (WSG) is the source of operational geological information on the rig and is responsible for all geology-related administrative wellsite activity. They are the operating company’s eyes and ears on the rig and as such, have to make sure that all possible geological and drilling information is gathered in a concise and timely manner.

While the wellsite geologist works in close cooperation with the company man on the rig he is not actually under his authority. Instead, the WSG reports directly to the “Operations Geologist” who is the “shore-based” intermediary between the geologist on the rig and the geology team in town who will be analyzing all the data. The unusual chain of command for disseminating key official geological data from the wellsite geologist follows this line of reporting:

WSG (rig) => Operations Geologist (town) => Drilling Superintendent (town) => Company Man (rig)

While the wellsite geologist is required to immediately notify the company man of any pertinent drilling and geological information, the company man generally cannot act on the information until the town-based drilling superintendent has officially confirmed it.

The wellsite geologist will report all key geological and drilling data to the operations geologist immediately as it comes to hand. It is then the responsibility of the “ops geo” to disseminate this information to all members of the onshore geology and drilling teams who need to know the information for decision-making.

All key drilling decisions are made in collaboration with every department involved in the drilling of the well to ensure that well control barrier criteria are met and any decisions made will not compromise the integrity of the well or process safety systems.

At the commencement of drilling, when the well will be drilled “riserless” with no cuttings coming to surface, there will often only be one wellsite geologist on the rig. There may be two or even three casing strings run before the riser is finally run and drilled cuttings are brought to the surface.

The wellsite geologist will be needed during these stages of drilling to confirm that suitable geological formations have been intersected in order to successfully set casing. This task is commonly referred to as “calling casing point”. It is critical that the casing shoe for the conductor and surface casing is set deep enough to withstand pressure from a “kicking” formation further down.

Surface casing is run to prevent caving of weak formations that are encountered at shallow depths. The wellsite geologist needs to identify when a competent formation is intersected to ensure that the formation at the casing shoe will not fracture at high hydrostatic pressure, which may be encountered later in the drilling of the well.

Because there are no drilled cuttings coming to surface all geological data is interpreted from one, or a combination of both, of the following sources:

  • Drilling parameters such as ROP (rate of penetration) and torque when there are no LWD (Logging While Drilling) tools in the BHA (Bottom Hole Assembly).
  • Real-time Gamma Ray and/or Resistivity data from downhole LWD tools.

Once the surface casing has been set and the BOP (blow out preventer) and riser are run to the seabed, all drilled cuttings will then be circulated to the surface, which means the days get a whole lot busier for the wellsite geologist. From this stage on there will generally be two wellsite geologists operating back-to-back 12-hour shifts.

Responsibilities

As the acting representative for the operating company’s geology team, the wellsite geologist will have the following responsibilities:

  • Evaluating offset data before the start of drilling
  • Analyzing, evaluating and describing formations while drilling, using cuttings, gas, formation evaluation measurement while drilling (FEMWD) and wireline data
  • Comparing data gathered during drilling with predictions made at the exploration stage;
  • Advising on drilling hazards and drilling bit optimization
  • Making decisions about suspending or continuing drilling. Ultimately, it’s the wellsite geologist’s responsibility to decide when drilling should be suspended or stopped.
  • Advising operations personnel both on the rig and in the onshore operations office about any pertinent geological or drilling information as it arises.
  • Supervising mudlogging, MWD (Measurement while drilling)/LWD (logging while drilling) and wireline services personnel and monitoring quality control in relation to these services.
  • Keeping detailed records, writing reports, completing daily, weekly and post-well reporting logs and sending these to appropriate departments.
  • Maintaining up-to-date knowledge of LWD and MWD tools and status of all equipment onboard and in transit to make sure the equipment is available and in working order when it is needed.

In expected HPHT (high-pressure high temperature) wells it is critical the wellsite geologist can identify (and immediately communicate) any identifying signs of increases in pore pressure. These can include the following telltale signs:

  • Changes in flow rate and active mud system volumes. If the formation pressure becomes higher than the hydrostatic pressure being exerted by the circulating drilling fluid then the mud will become “underbalanced” and the well will “kick”. If this kick isn’t detected early enough then a catastrophic blowout could occur.
  • Presence of “cavings” coming over the shakers. When drilling over-pressured shales, it is common for the formation to undergo stress relief causing chips of rocks to cave from the borehole wall. These overpressure “cavings” tend to be larger than normal cuttings and maybe concave or propeller-shaped.
  • Increase in ROP (rate of penetration) and volume of cuttings. A pressure transition zone will make drilling easier because of the trapped water-reducing compaction and the increase in pore pressure reducing differential pressure, allowing cuttings to be released more easily into the mud stream.
  • Changes in LWD data, in particular, resistivity and sonic, density and neutron.
  • Changes in drilling parameters, especially torque, drag, and overpull. This can be due to deterioration of borehole integrity causing an increase in the volume of cuttings and cavings in the circulating mud.
  • The rise in background gas level, changes in the composition of the gas, or presence of “connection” gas, which is a result of swabbing downhole hole when the pumps are turned off to make a connection (add another stand of drill pipe).
  • Changes in pump pressure. An influx of gas into a well may reduce the density of the drilling fluid and therefore it will require less pressure to circulate the drilling fluid.
  • Change in properties of mud.
  • Changes in downhole temperature. Generally, there will be a slight decrease in temperature immediately above the over-pressured zone and then a steady increase with depth at a higher rate than in the normally pressured zone above.

If the wellsite geologist identifies any potentially hazardous changes in the drilling, the driller and company man must be notified immediately, and then the operations geologist will be notified.

If a potentially dangerous situation is recognized then the drilling will be stopped immediately while the company man either makes a decision on what to do next or waits for official instructions from the drilling superintendent in town on how to proceed.

The wellsite geologists spend most of their time working in the mudlogging unit (like the hardworking one in the photo above J), which is where all the monitoring equipment for the rig is located and also where the mudloggers/sample catchers will deliver the cuttings samples for them to inspect and describe.

All rock cuttings are inspected under a microscope and a detailed description is written for every sample that is generally collected in composite 5, 10 or 20 m intervals.

Cuttings Descriptions

cuttings-Amanda

The cuttings descriptions need to be very detailed and follow an industry-standard format that includes (but is not restricted to) the following observations:

  • Rock types and percentage of each found in the sample
  • Color
  • Texture
  • Grain or crystal size
  • Sphericity, roundness, and sorting of sandstone grains
  • Type of cement and/or matrix
  • Any fossils or accessory minerals
  • Presence of hydrocarbon indications, such as fluorescence or “show”
  • Estimate of porosity

A detailed well log is created combining all the cuttings information, LWD, and MWD data and drilling parameter data, and submitted along with a daily report every 24 hours. When the wellsite geologist finishes the shift and hands over to the next shift they have to have all of the reporting and samples descriptions up-to-date at the time of them handing over.

To become a wellsite geologist, you’ll need a degree in geology or possibly even chemistry, geochemistry or geophysics. There is no formal wellsite geologist qualification, but you would need to obtain knowledge in areas such as wellsite and offshore safety management, wellsite operations, formation evaluation of wireline, FEWD logs, and risk assessment before starting as a wellsite geologist.

Most wellsite geologists start their offshore career working as a mudlogger, MWD engineer or mud engineer and gain knowledge in the fields that a WSG is responsible for. They also need to possess supervisory skills, the ability to work well under pressure and the ability to quickly make decisions.

As most wellsite geologists work as independent consultants and are employed on a contracting basis, it’s up to them to handle their own career progression. Any wellsite geologists who progress beyond this position will generally move into an operations geologist role, with a few even moving up into company man positions.

While a wellsite geologist might earn a lot per day there is little job security, and quite often no permanent rotation. They may only get flown onto the rig the day before drilling operations begin and flown off again immediately after the well is completed or wireline logging is completed. The date of your arrival and departure is quite often only known within days of it occurring so long-term social commitments are impossible to plan. You can either expect to have to fly out to the rig at very short notice or have unplanned months without any work…or even years when the industry is going through a downturn.

Like with many oil and gas roles, being a wellsite geologist can be a very demanding job but the rewards can certainly outweigh the risks if a sensible approach is taken to managing your time and finances. If unpredictability is not your thing then wellsite geology is not for you! Being away from home for several months of the year is part and parcel of the job so people with young families may find this job too demanding on their family life. This will always be the first and foremost decision you will have to make if considering to become a wellsite geologist.

This article is written by Amanda Barlow. Amanda Barlow is a wellsite geologist and published author of “Offshore Oil and Gas PEOPLE – Overview of Offshore Drilling Operations” and “An Inconvenient Life – My Unconventional Career as a Wellsite Geologist”.

Amanda Barlow
Ms. Amanda Barlow

Another great book you may want to read if you like to get an overview of oil exploration, drilling and production is “The Story of Oil and Gas”: How Oil and Gas Are Explored, Drilled and Produced”.

 

About Dr. Roland N. Horne

 

Roland Horne 2018_03-1
Dr. Roland N. Horne

Dr. Roland N. Horne is the Thomas Davies Barrow Professor of Earth Sciences at Stanford University, and Senior Fellow in the Precourt Institute for Energy. He was also formerly Chairman of the Petroleum Engineering Department from 1995 to 2006.

He holds BE, Ph.D. and DSc degrees from the University of Auckland, New Zealand, all in Engineering Science.

He is best known for his work in well test interpretation, production optimization, and analysis of fractured reservoirs.

He is an internationally-recognized expert in the area of well test analysis and has twice been an SPE Distinguished Lecturer on well-testing subjects.

Under him, more than 50 people have obtained Ph.D. degrees at Stanford University.  Currently, Stanford University is recognized as one of the top schools in the world for the study of well test interpretation.

Prof. Horne has written more than 90 technical papers, is the author of the book Modern Well Test Analysis and co-author of the book Discrete Fracture Network Modeling of Hydraulic Stimulation. He is an SPE Honorary Member, and a member of the National Academy of Engineering in the USA.

Roland Horne is also recognized as an expert in geothermal resources. He received Geothermal Special Achievement Award from Geothermal Resources Council in 2015. He is the Technical Programme Chair of World Geothermal Congress 2020 in Reykjavik and a member of the GRC Board of Directors.

Dr. Horne will conduct a 5-day course – Modern Well Test Analysis – on August 26-30, 2019 in Singapore. This highly regarded course has been attended by thousands of oil and gas, as well as geothermal professionals in many countries for more than 20 years. If you want more information about the course, please contact LDI Training at lditrain@singnet.com.sg.

The Top Ten Oil Refineries in Southeast Asia

1.    Exxon Singapore Refinery – 592,000 BPD – Singapore

With a design capacity of about 592,000 barrels a day, the Exxon Singapore Refinery in Singapore is the largest refinery in South East Asia. It is also ExxonMobil’s largest in the world.

Located in Jurong Island of Singapore, the refinery became the largest as it is made up of the former Mobil and Esso refineries which operate as one facility, following the merger of Exxon and Mobil in 1999.

ExxonMobil recently completed the refinery expansion to upgrade of the production of its proprietary EHC Group II base stocks.

It also has an ongoing multibillion-dollar expansion to enable the refinery to convert fuel oil and other bottom-of-the-barrel crude products into higher-value lube base stocks and distillates.

 

2.    Shell Pulau Bukom Refinery – 458,000 BPD – Singapore

Royal Dutch Shell’s refinery at Pulau Bukom in Singapore has the capacity to process 458,000 barrels of crude oil per day.

It recently completed the expansion to increase the storage capacity by nearly 1.3 million barrels by building two large crude oil tanks.

The refinery is the company’s largest wholly-owned Shell refinery globally in terms of crude distillation capacity.

 

3.    Pertamina Cilacap Refinery – 348,000 BPD – Indonesia

With a total combined capacity to process 348,000 barrels of oil per day, the Pertamina Cilacap refinery consists of Oil Refinery I and Oil Refinery II. The Cilacap refinery is Pertamina’s largest and is located in Cilacap in Central Jawa of Indonesia.

Oil Refinery I was constructed in 1974 with a design capacity of 100,000 barrels of oil per day. In 1998, to meet the growing demand for fuels and lube oil, the refinery underwent a Debottlenecking Project which increased its crude oil processing capacity to 218,000 BOP. The refinery was designed to process crude oil from the Middle East.

Oil Refinery II was built in 1981 with a design capacity of 220,000 BOPD. It is capable to process the crude oil from Indonesia and The Middle East.

 

4.    Singapore Refining Corporation Jurong Island Refinery – 285,000 BPD – Singapore

Located in Jurong Island of Singapore, the Singapore Refining Corporation Refinery was originally constructed in 1979 to process 70,000 BOPD. It was later expanded to increase its capacity to 285,000 BPD.

Singapore Refining Corporation is currently owned by Chevron and PetroChina. PetroChina became a co-owner of the refinery following its purchase of Keppel Corporation’s stake in the refinery in 2009.

 

5.    PTT Rayong Refinery – 280,000 BPD – Thailand

PTT Rayong Refinery started in 1996, is owned by PTT Aromatics and Refining Public Company. Currently, the refinery has a design capacity of 280,000 BPD following the completion of an expansion of its condensate splitting capacity and connected units in 2009.

The refinery is located in Sriracha, Thailand. PTT Group became the sole owner of the refinery when Shell International sold its 64 percent stake in the refinery to state giant PTT Plc.

 

6.    Thai Oil Refinery – 275,000 BPD – Thailand

The Thai Oil Refinery is a large high complexity refinery capable of processing 275,000 barrels per day. Located at Sriracha, Thailand, the refinery was originally commissioned in 1961 with a capacity of 35,000 BPD. It underwent several expansions subsequently to increase its processing capacity to its current level.

Currently, the refinery is being further expanded and upgraded. The expansion project will increase daily crude throughput from 275,000 barrels to 400,000 barrels.

 

7.    Pertamina Balikpapan Refinery – 260,000 BPD – Indonesia

The Pertamina Balikpapan Refinery has a very interesting and long history. It was built by Shell Transport and Trading Ltd in 1922, during the Dutch colonial times, following the discovery of oil in Balikpapan in East Kalimantan in 1897. The discovery was named Mathilda as it was drilled by Mathilda Corporation.

Pertamina acquired the refinery from Shell in 1966 and subsequently expanded the capacity of the refinery to its current level.

The refinery is currently being expanded further to increase its capacity from 260,000 to 360,000 BPD.

 

8.    IRPC Rayong Refinery – 215,000 BPD – Thailand

Located at Rayong, Thailand, the IRPC Rayong Refinery has a capacity to process 215,000 barrels of oil per day. It is a large refinery and integrated petrochemical complex and is designed to handle condensate and crude oil.

 

9.    Petron Bataan Refinery – 180,000 BPD – The Philippines

Located at Bataan in the Philippines, Petron Bataan Refinery has a designed capacity of 180,000 barrels per day. The refinery started in 1961 and is owned by Petron Corporation.

 

10.  Petronas/Phillips66 Melaka II Refinery – 170,000 BPD – Malaysia

Located in Melaka, Malaysia, the Petronas/Phillips66 Melaka II Refinery has an installed capacity of 170,000 barrels of oil per day.

The refinery was commissioned in 1999 with an initial capacity of 100,000 BPD. Its crude oil processing capacity increased to 170,000 BPD after it underwent a debottlenecking project in 2007.

PETRONAS became the sole owner of the refinery in 2014 when it acquired the 47% stake of Phillips 66 in the refinery.

 

Pertamina Dumai Refinery reduces its fuel costs by 40%

IMG20180924180432-cropped.jpg
The PLN power plant at Muara Karang, Jakarta.

Pertamina has completed the construction of the 67 km gas pipeline supplying gas to its Unit II Refinery in Dumai. With the commissioning of the 24-inch pipeline on 14 April 2019, the fuel needed to operate the refinery is now supplied by the gas produced from the nearby gas fields.

The gas comes from the following three blocks:

  1. The prolific Grissik field located in the Corridor Block which is operated by ConocoPhillips. The Grissik field produced more than 900 MMSCF of gas per day in 2018. With an area of 2258 square kilometer, the Corridor Block is one of the largest gas blocks in Indonesia. Other very large gas blocks are the Tangguh and the Mahakam blocks.
  2. The fields located in the Bentu Block which is managed by PT Mega Energi Persada (PT EMP). The Bentu Block is located near the city of Pekanbaru. PT EMP also supplies its gas to Indonesia’s state power company (PLN) and Riau Andalan Pulp and Paper (RAPP).
  3. The oil and gas fields located in the Jambi Merang Block which is now operated by Pertamina Hulu Energi Jambi Merang (PHE Jambi Merang). PHE Jambi Merang acquired the block from the Joint Operating Body Pertamina-Talisman Jambi Merang on 9 February 2019.

In the past, the refinery used the fuel oil, Naptha and fuel gas it produced internally to meet the fuel needs of the refinery.

The project has brought significant economic benefits to both the gas producers and the refinery. In using the gas, the refinery is able to reduce its fuel costs by 40%.

The Top 10 Crude Oil Producing Companies in Indonesia in 2018

westseno
The photo showed the drilling activity at the West Seno field, the first deepwater field in Indonesia. The photo was taken by Dr. Tony Tirta.

The average crude oil production in Indonesia in 2018 is 803,000 barrels per day according to SKK Migas of Indonesia.

Here are the top ten crude oil producing companies in Indonesia in 2018.

Chevron Pacific Indonesia – 209,000 BOPD

Chevron is the biggest oil producer in Indonesia in 2018 and has been a leading oil producer in Indonesia for more than 90 years. It started operating in Indonesia in 1924 under Standard Oil Company of California.

Chevron operated oilfields in Sumatera and East Kalimantan. It’s East Kalimantan assets came from the acquisition of Unocal in 2005. Chevron handed back all the assets in East Kalimantan to Indonesia government on October 24, 2018, after 50 years of operation under Unocal and Chevron.

Currently, Chevron’s oil production comes mainly from the oil fields located in Riau, Sumatera under the Rokan Production Sharing Contract. The biggest oil field in the Rokan PSC is the Duri field which has been under steam-flood since 1985 and is one of the largest steam flood projects in the world.

ExxonMobil Cepu Ltd – 208,000 BOPD

ExxonMobil Cepu Ltd is the operator of the Cepu block located in Central Java and East Java. The Cepu Cooperation Contract (KKS) was signed on 17 September 2005 and will continue until 2035. ExxonMobil holds a 45% interest in the Cepu block.

ExxonMobil started exploration in 1999, and the oil from the Banyu Urip field started to flow in December 2008.

Pertamina EP – 79,000 BOPD

Pertamina EP operated 21 oil and gas fields located in various parts of Indonesia. These oilfields are managed under five asset groups based on their geographical locations.

Located in North Sumatera and some part of South Sumatera, the Asset One oilfields include Rantau Field, Pangkalan Susu Field, Lirik Field, Jambi Field, dan Ramba Field.

Located in South Sumatera, the Asset Two oilfields include Prabumulih Field, Pendopo Field, Limau Field dan Adera Field.

Located in West Jawa, the oilfields included in Asset Three are Subang Field, Jatibarang Field dan Tambun Field.

Located in Central and East Jawa, the Asset Four oilfields include Cepu Field, Poleng Field dan Matindok Field.

Located in Eastern part of Indonesia, the oilfields in Asset Five are Sangatta Field, Bunyu Field, Tanjung Field, Sangasanga Field, Tarakan Field dan Papua Field.

Pertamina Hulu Mahakam – 42,000 BOPD

Pertamina Hulu Mahakam became the operator of the oil and gas fields located in the Mahakam Block on 1 January 2018. The fields were previously discovered and operated by Total along with Inpex as its partner. They acquired the block in 1966.

Several giant oil and gas fields are located in this block such as the Handil field, the Tunu field, and the Peciko field.

Pertamina Hulu Energi OSES (Offshore South East Sumatera) – 30,000 BOPD

Pertamina Hulu Energi OSES became the operator of the oil fields in Block South East Sumatera on September 6, 2018. The fields were previously operated by CNOOC, China National Offshore Oil Company.

Pertamina Hulu Energi ONWJ – 29,000 BOPD

Pertamina Hulu Energi ONWJ (PHE ONWJ) is currently the operator of the  Offshore North West Java (ONWJ) production sharing contract following the change of company ownership from BP to Pertamina in July 2009.

The contract area, located in the Java Sea, covers an area of approximately 8,300 square kilometers – stretching from the North of Cirebon to Kepulauan Seribu.

The giant Ardjuna field is located in this Production Sharing Contract area. It was discovered by ARCO – Atlantic Richfield Company –  in 1969 and operated by ARCO until BP – British Petroleum – acquired ARCO in 2000.

The production facilities consist of 670 wells, 170 shallow water platforms, 40 processing and service facilities and some 1,600 kilometers of sub-sea pipeline.

Medco EP Natuna – 16,000 BOPD

Medco EP Natuna, a subsidiary of Medco Energi, is the operator of the South Natuna Sea Block B. The field was initially operated by ConocoPhillips until Medco Energi acquired it in 2016.

Besides producing oil, Medco EP Natuna also supplies gas to Singapore using a 656 KM long 28” subsea pipeline.

Petronas Carigali (Ketapang) – 15,000 BOPD

Petronas Carigali Ketapang operates the Bukit Tua Field located in the Ketapang Block in East Java. Bukit Tua is an oil field but with a significant amount of associated gas. The offshore field is situated at a water depth of about 57 m.

The production facilities consist of wellhead platforms, an FPSO – Floating Production, Storage and Offloading – and onshore receiving facilities (ORF) in Gresik.

PetroChina International Jabung – 14,000 BOPD

PetroChina International Jabung operates the prolific Jabung Block located in Jambi in Central Sumatera.

The company produces crude oil, condensate, LPG and gas. PetroChina supplies gas to Singapore using a 450 KM long subsea pipeline.

An interesting aspect about the block is that PetroChina discovered the fractured basement rock contains a significant quantity of gas can flow at significant rates.

Pertamina Hulu Kalimantan Timur – 13,000 BOPD

Pertamina Hulu Kalimantan Timur operates the East Kalimantan-Attaka Work Area. Chevron was the previous operator of the work area until it handed over the operatorship to Pertamina on October 25, 2018.

Attaka, the famous giant oil field is located in this block. The Attaka field was discovered and operated by Unocal until Chevron acquired it in 2005.

The oil fields in this work area are in the late declining phase. Around one billion barrels of oil and 3 TCF of gas have been produced from this work area.